Process for inhibiting scale formation in oil well brines

ABSTRACT

A method for introducing an inhibitor, e.g. an inhibitor against scale formation, into oil well brines is disclosed. This method comprises introducing into the porous reservoir structure, i.e. oil-bearing formation adjacent to the bore of an oil well a relatively water or brine insoluble polyvalent metal salt of the inhibitor, e.g. polyacrylic acid and/or hydrolyzed polyacrylamide, the polyacrylic acid having a molecular weight range of about 17,000 to 50,000, and the hydrolyzed polyacrylamide having from about 10 to 50 percent unhydrolyzed amide groups and a molecular weight of about 1,000 to 8,000, in which the metal is selected from the group consisting of alkaline earth metals, Zn , Cu , Pb , Fe , Cr , and Al . The method comprises in situ formation of the relatively water or brine insoluble polyvalent metal salt of the inhibitor, e.g. polyacrylic acid and/or hydrolyzed polyacrylamide, in the reservoir structure by introducing into the porous structure a water-soluble salt of the inhibitor, e.g. the sodium salt of the polyacrylic acid and/or hydrolyzed polyacrylamide, and a watersoluble salt of the polyvalent metal in a strongly acidic, aqueous solution. In the in situ method the strong acid in solution initially inhibits reaction of the salts but is dissipated by the fluids in the oil-bearing formation and neutralized by the formation rock to allow reaction and formation of the desired water-insoluble metal salt of polyacrylic acid and/or hydrolyzed polyacrylamide in the formation.

United States Patent [151 3,704,750 Miles et al. [45] Dec. 5, 1972 [54]PROCESS FOR INHIBITING SCALE FOREIGN PATENTS OR APPLICATIONS FORMATIONIN OIL WELL BRINES Inventors: Leon II. Miles, Plano; Graham E. King,Dallas, both of Tex.

Assignee: Atlantic Richfield Company, New

York,N. Y.

Filed: Nov. 25, 1969 Appl. No.: 879,919

Related US. Application Data Continuation-impart of Ser. No. 789,927,Jan. 8, 1969, abandoned.

US. Cl. ..166/279, 166/300, 166/308, 25218.55 R, 252/855 B Int. Cl...C02b 5/06, E2lb 43/25, E2lb 43/26 Field of Search ..252l8.55 B, 8.55A, 8.5 C, 252/180, 181; 210/58; 166/308, 300, 279,

References Cited UNITED STATES PATENTS 2/ Qreat Britain ..252/l8l [5 7ABSTRACT A method for introducing an inhibitor, e.g. an inhibitoragainst scale formation, into oil well brines is disclosed. This methodcomprises introducing into the porous reservoir structure, i.e.oil-bearing formation adjacent to the bore of an oil well a relativelywater or brine insoluble polyvalent metal salt of the inhibitor, e.g.polyacrylic acid and/or hydrolyzed polyacrylamide, the polyacrylic acidhaving a molecular weight range of about 17,000 to 50,000, and thehydrolyzed polyacrylamide having from about 10 to 50 percentunhydrolyzed amide groups and a molecular weight of about 1,000 to8,000, in which the metal is selected from the group consisting ofalkaline earth metals, Zn, Cu, Pb, Fe Cr***, and AI The method comprisesin situ formation of the relatively water or brine insoluble polyvalentmetal salt of the inhibitor, e.g. polyacrylic acid and/or hydrolyzedpolyacrylamide, in the reservoir structure by introducing into theporous structure a water-soluble salt of the inhibitor, e.g. the sodiumsalt of the polyacrylic acid and/or hydrolyzed polyacrylamide, and awatersou le salt of th 01 v lent eta in a tr n1 acidic, aqueous solutionn the in situ metl iog 01% strong acid in solution initially inhibitsreaction of the salts but is dissipated by the fluids in the oil-bearingformation and neutralized by the formation rock to allow reaction andformation of the desired water-insoluble metal salt of polyacrylic acidand/or hydrolyzed polyacrylamide in the formation.

23 Claims, No Drawings This application is acontinuation-in-part ofapplication Ser. No. 789,927, filed Jan. 8, 1969, now abandoned.

This invention relates to a method for introducing inhibitors such asthose for inhibiting scale formation of oil well brines by placing at ornear the bottom of the well or in the oil-bearing formation a relativelywaterinsoluble, i.e., very slowly soluble inhibitor, e.g., scaleinhibiting agent which is effective in small quantities. Moreparticularly, this invention relates to the use of polyvalentmetal saltsof inhibitors, such as polyacrylic acids and/or hydrolyzedpolyacrylamides, the polyacrylic acids having a molecular weight ofabout 17,000 or 20,000 to 30,000 or 50,000 and the hydrolyzedpolyacrylamide having from about to 50 percent unhydrolyzed amide groupsand, a molecular weight of about 1,000 to 8,000, which can be formed byreaction of a water-soluble metal salt of the polyacrylic acid and/orhydrolyzed polyacrylamide and a water-soluble salt of a polyvalentmetal. While the present invention will be described with referencehereinbelow to scale inhibitors, and more particularly, to the use ofmetal salts, polyacrylic acids and/or hydrolyzed polyacrylamides asscale inhibitors in oil well brines, the present invention broadlyincludes the in situ deposition of any inhibitor, commonly used in oilbearing formations, by the method described herein, that is, byintroduction of the inhibitor into the oilbearing formation as two ormore water-soluble components in strong acidic solution and reactionand/or precipitation of the water-insoluble inhibitor as the acidicsolution is dissipated to place the desired relatively water-insolubleinhibitor in the formation.

Scale deposits from oil well brines and their attendant problems, e.g.,increased costs and efficiency loss, are well known in the art. Scalemay be defined as a deposit formed on surfaces in contact with water.The most common scales associated with oil field brines are calciumsulfates, barium sulfate and calcium carbonate. Other insoluble sulfatesand carbonates may be classified as scale, but are usually found insmall quantities along with the three previously mentioned. Corrosionproducts such as iron oxide and iron sulfide may also be considered asscale. In particular, calcium sulfate, barium sulfate, and calciumcarbonate scales deposited upon water contact surfaces in the vicinityof the well bore, in downhole equipment and in surface facilities of aproducing well have caused substantial problems such as obstruction offluid flow, impedance of heat transfer, wear of metal parts, shorteningof equipment life, localization of corrosion attack, poor corrosioninhibitor performance and unexpected equipment shutdown.

Many industries are faced with problems in the treatment of scales, butthose handling brines from deeply buried earth formations are plaguedwith a unique combination which makes scale control very difficult. Suchlarge volumes of water, very poor water quality,

1 severe temperature and pressure conditions and the very remote andnearly inaccessible location for treatment where trouble begins are afew of such problems.

Prevention of scale requires an understanding of the conditions underwhich scale is formed. Three major causes have been identified. Theseare a mixture of two incompatible waters, changes in physicalenvironment and changes in chemical environment. One incompatiblemixture possibility in oil wells is water entry from well casing leaksor poor casing cement jobs above or below the producing interval or oilbearing formation. Obviously, this problem can often be solved by moredirect methods than by using scale inhibitors. Another mixturepossibility not so easily overcome may occur during water floodingoperations at producing wells when injection water from an input wellbreaks through. It has been shown that no reaction occurs within theformation pore spaces when water incompatible with formation water isinjected. The discrete pore channels are filled with injection waterdisplacing formation water during flooding operations and no opportunityfor intimate mixing is presented until both formation water andinjection water, produced from separate pore channels make contact atthe producing well bore face. If these two waters are incompatible,however, there will be some ratio of one to the other which will causeprecipitation and scale in the producing well.

No intermixture of water in the formation or well is necessary for scaleformation if the brine contains a saturated solution of any salt atbottom-hole conditions. A change in physical environment as formationwater moves from the formation into the well bore or from the bottom ofthe well bore to the surface can be sufficient to cause deposition. Thisis the most prevalent cause of calcium sulfate scale. As an example,most Permian formation waters in West Texas are so intimately in contactwith anhydrite and gypsum that calcium sulfate saturation at conditionsof formation temperature and pressure is almost a certainty. Eveninjection water from other sources quickly becomes saturated as itpasses through these formations.

Chemical environmental changes are also associated with changes intemperature and pressure because of carbon dioxide and hydrogen sulfidegases dissolved in water. In the presence of acid gases, large amountsof calcium bicarbonate can be held in solution. Removal of these gasescauses the calcium bicarbonate to change to insoluble calcium carbonate.The amount of calcium carbonate precipitated by removal of CO gas from atypical Wyoming formation water can be as high as 0.8 lbs. per barrel ofproduced fluids.

Once the conditions are set for precipitation, the formation of a scaledeposit undergoes several stages. The initial combination of two ions iscalled the solute molecule. A loosely bound but orderly arrangement ofseveral molecules then forms a lattice which governs the final shape ofthe crystal. A more closely bound combination of several thousand solutemolecules forms a nucleus or seed from which the crystal grows. At thisstage the particle is too small to be seen with a microscope, and wouldeven pass the finest filter. Rapid growth from the nucleus stage resultsin a filterable, microscopic crystal, causing visible turbidity inwater. Eventually crystals grow large enough to be seen and finallydevelop into growths of very large proportion which we call scale. Thenucleating surface does not necessarily need to be a crystal nucleus ofthe scale forming mineral. Any similar substance will serve as afoundation on which scale can grow gypsum,

dolomite, cement, or even iron. Some industries avoid scale buildup,often at great expense, by coating systems with non-nucleating surfaces.

Various means to combat scale formation and its resultant disadvantageshave been employed. One of these has been removal and scraping of thepipes for reuse. This method is inadequate because of the long shut-downperiod involved and the short term effects of the work. Additionally,this method of combating scale formation does not alleviate the problemof scale form? ing in the pores of the oil-bearing formation, e.g., rockor sand formation through which oil must seep to reach the well andpumping areas. Another method employed in the art to combat scaleformation has been the use of chemical removal agents, e.g.,hydrochloric acid, pumped, typically along with a corrosion inhibitor,into an oil or water well. Although this method is effective to someextent, the removal agents have failed to prevent scale formation andhave sometimes had a deleterious effect on various parts of the metallicequipment. Attempts have also been made tocombat scale by introducing anadditive down the casing annulus of the well, but such additivetreatments again have generally proved unsatisfactory as they fail toremove existing scale and only inhibit the growth of scale in piping andother surfaces. Also additive treatments heretofore known generally,require the use of large" amounts of additives and frequent retreatment.While recently slow-release additive systems in which glasslikepolyphosphate salts or pelletized carboxymethyl cellulose mixed saltshave been used, such salts are generally disadvantageous, particularlyin oil well brines because the dissolving polyphosphates revert rapidlyto inactive orthophosphates and the carboxymethyl cellulose saltsrequire a relatively high dosage and have a short period ofeffectiveness. Additionally, in the chemical treatments heretofore used,many methods of applying the inhibiting agent have been used. Forexample, liquid inhibitors have been squeezed into well bores and intofracture planes in the formation. However, the inhibitor feedback, i.e.,release of the inhibitor into the fluids to inhibit scale formationrelies on adsorption-desorption of the inhibitor from the sand grains,or in the alternative depends on the differential pressure along thefracture face to meter the inhibitor into the produced fluids, oil andwater. With the inhibiting agents used heretofore inadsorption-desorption, there is generally a largeamount of the agentthat is not adsorbed but is produced back, i.e., swept away with theproduced fluids, in large wasteful concentrations. In other cases theinhibiting agent is irreversibly adsorbed in the formation and noinhibiting agent is desorbed by the fluids to prevent scale formation.Squeezing liquid scale inhibitors into the well face or fracture face isalso practiced. But here also are found disadvantages as a large amountof the inhibiting agent is recovered almost immediately, thus reducingthe life of the treatment.

This invention has as one of its objects the addition of a new and novelinhibitor, i.e., inhibiting agent to oil wells to inhibit scale formedfrom oil well brines. The inhibitor is effective in small quantities anddoes not rapidly revert to an inactive form. The inhibitor is arelatively insoluble, e.g., very slowly soluble salt therebyguaranteeing slow feedback over extended periods of time. The inhibitoris a solid and can be used for placement at or near the bottom of anoil'well e.g., by packing in the well annulus, in a hydraulicallyinduced fracture, etc., or in a surface feed pot using recycle ofproduced fluids. Additionally, this inventionhas as an object a novelmethod by which an inhibitor, for example, the novel inhibitor describedbelow, can be formed in situ in the porous oil-bearing rock formationadjacent to a well bore or in a fracture plane emanating from the wellbore. The inhibitor, as it is slowly dissolved, will inhibit theformation of the various precipitates known as scale and prevent thedeposit of these scales in the rock formation in the vicinity of thewell bore, downhole equipment and surface facilities of a producingwell.

The novel inhibiting agents of this invention are water-insoluble metalsalts of relatively low molecular weight polyacrylic acids and/orrelatively low molecular weight hydrolyzed polyacrylamides, the metal ofwhich is a polyvalent cation which does not react in oil well brineswith the brine, oil or metal well parts. Suitable cations are thealkaline earth metals, Zn, Cu,

7 nucleation stage of the crystal in the brines.

The polyacrylic acid metal salts of this invention can be prepared byreacting an aqueous solution of a relatively' low molecular weight watersoluble metal salt, e.g., sodium salt of polyacrylic acid having amolecular weight in the range of about 5,000, or 7,000 up to about50,000 or even possibly 100,000 but, generally, the molecular weight isin the range of about 17,000 to 50,000, preferably from about 20,000 upto about 30,000 (e.g., about 300 repeating units), with a concentratedsolution of a water-soluble salt of the desired polyvalent cations suchas the chlorides of the alkaline earth metals, Zn Cu**, Pb*, Fe Cr***,and Al***. The molecular weights referred to also apply to the producedmetal salt of this invention and are determined by gel permeation gaschromotography comparison of the esterified polymer. In general, thehigher the molecular weight of the polyacrylic acid, and consequently ofthe produced metal salt, the less desirable is the produced metal saltas an inhibitor. In general, reaction of the water-soluble salts iscarried out by mixing at room temperature or slightly higher, e.g., upto about C. Preferably, the metal salt is added to an aqueous solutionof the polyacrylic acid salt until no more precipitate is formed. Anywater-soluble metal salt of polyacrylic acid and water solublepolyvalent metal salt can be used provided the polyvalent metal replacesthe metal cation of the polyacrylic salt to produce a water-insolublesalt of the polyacrylic acid.

The relatively water-insoluble polyvalent metal salt of polyacrylic acidis then separated from the aqueous sszmt ms -sv by filtzatiqn ssem r 9*.e m n stion, washed with water, and dried, e.g., at temperatures ofabout F. to F. Drying decreases the solubility of the polyvalent metalsalt in water andalso increases its crush strength. The resultant solidpolyvalent metal salt inhibitor can then be crushed to the desiredparticle size, or in the alternative, the solid can be extruded into anydesired shape before drying.

The low molecular weight hydrolyzed polyacrylamide component of thepresent invention can properly be termed apolycarboxyethylene-polycarbamylethylene long chain carbon-to-carbonpolymer. It is a polyelectrolyte. In the acid form the polymer has theprobable formula:

where n and m are whole numbers, suchthat n is at least about as largeas m, and not more than about 9 times as large as m, and n and m and xhave such size that the total molecular weight is between 1,000 and8,000, preferably between 4,000 and 7,000, and the two groups may occurin random order and orientation. The polyacrylamide has. from to 50percent unhydrolyzed amide groups, and preferably from about to about 40percent. Conveniently for in situ formation of the inhibitor, thepolymer is added as an alkali metal salt, usually the sodium salt.Potassium, ammonium or other soluble salts may be used, and all of theacidic hydrogens need not be replaced, nor of those replaced need thecation be the same. As the polymer is used in dilute solution, and thecation, be it alkali metal or hydrogen, etc., is dissociated to anextent that varies with the concentration of other cations present, thepolymer at the time of action can be considered in a transient state,and for purposes of convenience, the name of the acid form is used foridentification without the intention that the polymer be in such acidform. The hydrolyzed low molecular weight polyacrylamide in one specificembodiment is a dry light cream-colored solid having a molecular weightof 6,000, a polymer content of 75 percent, with the polymer being 75percent carboxyl and percent amide, and the diluents being primarilysodium and ammonium sulfates and sodium hydroxide. The pH of a 1 percentaqueous solution is10.8 and of a10 percent solution is 12.1. Thesolubility is over 25 percent in solutions having a useful viscosity.

While there is a relatively broad range of acceptable 4 particle sizefor the inhibitor, the particles desirably are small enough to enter theformation fracture and not so fine that they will be transported easilyinto the in terstices of the proponent sand used in sand fracturingprocesses. In normal fracturing operations a sand grain size andtherefore a desirable inhibitor particle size is in the range of about 6to 60, preferably about 20 to mesh. When the inhibitor is extruded, itcan be formed into sticks, or other shapes for dropping down the wellbore or casing.

The metal salts, polyacrylic acids and hydrolyzed polyacrylamides, asdefined above, can be" present singly, or in mixed form, with the molarratio of acid to acrylamide being from about 100:1 to 0.121, preferablyfrom about 9:1 to 1:1. The mixed form of metal salts of polyacrylicacids and hydrolyzed polyacrylamides can be prepared by reacting aconcentrated solution of a water-soluble salt of the desired polyvalentcation with a mixed solution containing both a water-soluble metal,e.g., sodium, salt of the low molecular weight polyacrylic acid and awater-soluble metal, e.g., sodium, salt of the hydrolyzedpolyacrylamide, the acid and acrylamide' being present within theaforementioned molar ratios. Alternatively, the mixture can be formed bymixing the solid polyvalent metal salts of each of the polyacrylic acidand hydrolyzed polyacrylamide in the desired molar ratios.

The method for in situ formation of an inhibitor in an oil bearingformation, e.g., formation of the polyvalent metal salt in theoil-bearing formation generally comprising introducing into the porousformation adjacent to the well bore, a strongly acidic aqueous solution,i.e., pH below about 1.5, containing a water-soluble salt of theinhibitor, e.g., sodium salt of polyacrylic acid and/or sodium salt ofhydrolyzed polyacrylamide, and a water soluble salt of the desiredpolyvalent metal. Generally, any strong acid, such as hydrochloric acid,can be used to" form the acidic aqueous solution, although sulfuric acidis not generally desirable since the sulfate ion presents scaleproblems. Other suitable acids are acetic, combinations of l-lCl andacetic, etc. The acid inhibits reaction of the water-soluble salts insolution, but upon introduction of the acidic solution into the well andformation surrounding the well, the acid is dissipated and in partneutralized by the produced fluids and the oil-bearing formation so thatthe water-soluble salts then react to produce the waterinsoluble metalsalt of the inhibitor. This process has an advantage over most in situprocesses known heretofore since, although the water insoluble salt isformed in situ it is produced as a mixture of the soluble and insolublesalts in the presence of an excess of water. Thereafter thewater-soluble portion of the mixture is rapidly dissolved from theformation, leaving only the insoluble salt. The advantage to this isthat the pores of the oil bearing formation are not plugged by theinhibiting agent and contact of the oil well brine and inhibiting agentis insured. This method of in situ formation of an inhibitor isapplicable to any inhibitor, particularly an organic inhibitorcomprising a relatively water-insoluble metal salt, e.g., polyvalentmetal salt of the organic inhibitor, precipitated upon reaction of awatersoluble salts of the metal, e.g., polyvalent metal, and awater-soluble salt of the organic or negative portion of the inhibitorin neutral, somewhat acidic or alkaline solution, but not precipitatedin strongly acidic, e.g., pH 1.5 or less, solution. The water-solublesalts used to form such inhibitors conversely include any such salts,i.e., the water-soluble metal salt and water-soluble salt of the organicor negative ion, which will not react and/or precipitate in stronglyacidic solution but will react and/or precipitate as the acid in thesolution dissipates to precipitate the desired inhibitor. In general,polyvalent metal salts of organic compounds tend to be water-insoluble,but acid-soluble, whereas alkali salts of such organic compounds tend tobe water-soluble. Accordingly, this method is particularly applicable tothe in situ formation and precipitation of polyvalent metal salts oforganic inhibitors. Suitable water-soluble polyvalent metal salts foruse in the in situ method of this invention include the chlorides of thepolyvalent metals and suitable water-soluble organic salts include thealkali metal salts, particularly sodium salts of the organic inhibitor.

Generally an amount of inhibitor is added to the well, or formed in situin the formation surrounding the oil well, sufficient to provide in theproduced fluids an amount of the inhibitor effective for the intendedpurpose, e.g., to inhibit the formation of solid scale 7 deposits suchas calcium or barium sulfate or calcium carbonate scale, at or near thebottom of the well. This effective amount is typically in the range ofabout 0.1 to 25 ppm, preferably about 0.25 to 10 ppm in the producedwater. The amount of inhibiting agents desired to be introduced into aparticular oil well for scale inhibition depends in fact upon suchfeatures as the composition of the oil well brine, i.e., amount of scaleforming minerals such as sulfates or carbonates, amount of waterproduced in the well, temperature of the formation, etc. which will varyfrom well to well, or formation to formation. Generally, for example,the inhibiting agents of this invention are more insoluble at highertemperatures so that more inhibitor will be required in the formation toprovide the desired concentration in the produced water. Also, althoughgenerally, oil well brines have a total concentration of scale formingminerals, e.g., calcium or barium sulfates, calcium ,carbonate, etc., inamounts up to several thousand, e.g., 2,000 parts per million, the useof the inhibitor of the present invention in even-smaller amounts, lessthan the desired amounts set forth above, will provide less scaledeposits in the oil well brine. When the inhibitor is formed in situ,the acidic solution introduced into the well will, of course, be drivena distance, e.g., several inches, 4 or 5, to several feet, 2 or 3, ormore, into the formation outwardly of the well.'lf desired, theinhibitor may be driven to greater distances outwardly of the well byfollowing the acidic solution with an overflush, such as water or oil.Since the amount of inhibitor required in the formation to provide thedesired concentration in the produced water is small, the concentrationof water-soluble salts in the acidic solution can be low. For example,to produce a salt of polyacrylic acid, e.g., calcium salt, in situ,water soluble sodium polyacrylate can be used as a one-half percentsolution of the salt up to such an amount, e.g., about 10 percent, wherethe density of the precipitated inhibitor is so high that theprecipitate plugs the formation. Preferably, the sodium polyacrylate isused in concentrations below about 5 percent by weight and usually inthe range of one-half to 1 percent by weight. While it would be optimumto use a stoichiometric amount of the polyvalent metal salt, usually alarge excess is used to insure complete reaction of the organicinhibitor, e.g., polyacrylate. For example, concentrations of aboutonehalf to 1% percent by weight Ca ion are used with one-half to 1percent solutions of the sodium polyacrylate. The same concentrationsapply for the water-soluble hydrolyzed polyacrylamide. The use of largeamounts of low concentration solution also is beneficial since itinsures wide distribution of the inhibiting agent outwardly from andaround the well base, thereby avoiding plugging of the formation andproviding full inhibition.

The following examples are set forth to more clearly illustrate thepresent invention, but are not to be considercd as limiting the scope ofapplicants invention.

EXAMPLE I The following is an example of effectiveness of the Zn salt ofhydrolyzed polyacrylamide having a molecular weight of about 1,000 to8,000 formed by reaction of ZnCl and hydrolyzed sodium polyacrylamide ofmolecular weight about 1,000. to 8,000 in aqueous solution of about pH 9to 9.5. The salt contains 20.25 percent Zn in its structure. A basesolution of a brine containing 100,000 mg./l. chloride ionand mg./lSO.,= is caused to form scale by adding BaCl crystals in excess. Theamount of barium sulfate formed was determined colorimetrically. To ablank test comprising a 1:1 mixtureof the base solution and distilledwater was added BaCI The amount of BaSO, formed was determined. A fourgram Zn polyacrylamide sample was added to one liter of distilled waterand permitted to stand for several days.v During this period, smallsamples of the solution were removed and filtered. The filtrate wasdiluted with various amounts of distilled water. The dilutents werecombined with the base solution and the diluted filtrate. BaCl was addedto the test solution containing Zn polyacrylamide and the BaSO, formedwas measured. TheZnf concentration of the filtrate was. determined byatomic absorption techniques. The results are set forth below.

TABLE Filtrate in the Test Solution Zn Concentration (remainder Time inthe filtrate is base solution) Inhibition 1 day 13 mg/liter 10.0 59 5.042 2 days 17 10.0 77 5.0 50 7 days 36 10.0 97 5.0 92 2.5 64 10 days 4610.0 100 .5.0 96 2.5 73 1.25 I 36 The percent inhibition is defined l00(W1, W)/W,,, where W,, is the weight of the precipitate formed per unitvolume in the blank test and W, is the weight of precipitate formed perunit volume in the testsolution. An extrapolation of the longer testshows that this amount of Zn polyacrylamide in a liter'of water willdissolvecompletely in approximately 1 year.

EXAMPLE II A calcium salt of the same hydrolyzed polyacrylamide istested in a similar manner as Example 1. Two grams of salt added to aliter of water showed a solubility of 100 mg./l. after 24 hours. After 3months approximately 70 percent of the polymer had dissolved and waseffective in inhibiting barium sulfate precipitation in concentrationsas low as 1 part of filtrate to parts of the base solution. These saltsare also effective in inhibiting CaCO; and CaSO, scale.

EXAMPLE 1]] Introduction of fluids and solids to an oil well for afracturing operation is accomplished with standard pumping andprocedures with the exception of blending sand and inhibitor. Treatmentconsists of 7,000 lbs. of 20-40 mesh sand, 1,000 lbs. of 2040 meshtreating chemical, and 10,000 gallons of gelled fracturing water. Thematerials are pumped into the well as follows:

v the produced water.

EXAMPLE IV t In Situ formation of an inhibitor was accomplished asfollows. A Berea core sample was saturated with a brine having thefollowing constituents:

95 .900 Chlorides Bicarbonate 21 Carbonates 4,680 Calcium 76 Sulfates449 (OH) Hydroxide 1 L6 pH (Note: The DH ion is not usually found in oilfield brines. In this case it was added in the place of CO, to reactwith the acid treating solution so that no gas would be formed. Gassaturation would have interfered with the permeability measurements asit was desired to evaluate the polssgbility of core blockage orpermeability reduction by the polymer sat.

A treating slug of 0.05 pore volumes was'injected into the A" face ofthe core. The slug consisted of the following:

of 37% HCI acid of a 18.2% sodium polyacrylamide solution, MW L000 to8.000 of a brine containing 97,000 ppm Chlorides 74 ppm Sulfates 4,960ppm Calcium 6.45 pH 0.1 Bicarbonates 0 Carbonates The slug was displacedfrom faces A to B of the core with 0.7 pore volume of a brine having thesame properties as the slug brine. Analysis of the effluent at B showedno polymer was produced or lost from the core during the displacingprocess. Injection of the same displacing brine was begun from A to B,representing flow from a formation to a well bore. Analyses of samplesshowed production of a calcium polyacrylamide inhibitor in sufficientquantities to inhibit the formation of scale. The polymer was notproduced at an excessively high rate during the first 2 pore volumes asis common in a chemical squeeze job that relies on adsorptiondesorptionto maintain a slow chemical feedback.

After 7.5 pore volumes of brine had been produced, the polymerconcentration or production rate could be analyzed as a first orderequation of the form y 30 log x 2 l. y mg of the polymer produced. x No.of pore volumes of throughput. Core permeability measurements indicatedno reduction in permeability from in situ precipitation of the polymersalt.

EXAMPLE V The in situ precipitation of calcium polymer salts wasvisually observed in a micro visual cell. A glass cell represented aporous medium, the cell being a monolayer packed in a hexagonal mannerwith 0.007 inch diameter glass beads. The pore volume of the cell was0.89 cc and the consistent and low pump rates were possible by use of alow volume constant rate pump.

Through the use of time lapse photography, and a 200 power microscope,it was shown that in situ precipitation of a polymer salt does occur.The polymer salt could be seen adhering to the glass beads and in theinterstices of the beads. The cells showed that most of theprecipitation occurred in aband near the interface of the polymersolution and the cell saturating solution. In the cells that wereflushed or backflowed with 2 pore volumes of brine, there was no visualremoval of the polymer salt and practically no migration of polymer saltfrom its original location in the cell. All micro visual studies wereconducted using the solutions described in the core study data.

EXAMPLE VI Fifty wells have been treated by the method of thisinvention. No surface indications of scale have been recorded, althoughthe production areas are subject to severe scale problems. Two wellswere inspected approximately 2 months after treatment due to mechanicalproblems. There was no evidence of scale formation on the downholeequipment. Typical field treatment has been to use a mix of 60 bbls.lease water, gallons 15% HCI acid, and gallons of an 15-18 percentsodium polyacrylamide, MW 1,000 to 8,000 solution which is squeezed intothe formation and flushed with approximately 200 bbls. of lease water.The lease water contains 8,000-10,000 ppm calcium.

EXAMPLE VII Copper, lead, iron, chromium, aluminum and magnesiumpolyacrylamides equivalent to those identified in Examples 1 and II areadded to an oil well brine to inhibit scale formation.

EXAMPLE VIII EXAMPLE IX The zinc salt of polyacrylic acid having amolecular weight of about 17,000 to 20,000 formed by the reaction ofZnCl and sodium polyacrylate of molecular weight about 17,000 to 20,000in an aqueous solution of about pH 9 to 9.5 is added to an oil wellbrine to inhibit scale formation.

EXAMPLE X Y The calcium salt of polyacrylic acid having a molecularweight of about 17,000 to 20,000 formed by the reaction of CaCl, andsodium polyacrylate of molecular weight of about 17,000 to 20,000 isadded to an oil well brine to inhibit scale fon'nation.

EXAMPLE x1 Copper, lead, iron, chromium, aluminum and magnesiumpolyacrylates equivalent to those identified in Examples 1X and X areadded to an oil well brine to inhibit scale formation.

EXAMPLE X11 Zinc, calcium, copper, lead, iron, chromium, aluminum andmagnesium polyacrylates are formed in situ using the method of Examples1V and V by reacting the corresponding metal chloride and sodiumpolyacrylate in HCl solution (pH 1.5) and precipitating the desiredpolyacrylate as the acid is dissipated.

1t is claimed:

1. A method for inhibiting scale formation in oil well brines whichcomprises introducing into the oil well a relatively water-insolublepolyvalent metal salt of at least one of polyacrylic acid and hydrolyzedpolyacrylamide, in which the polyvalent metal is selected from the groupconsisting of alkaline earth metals, Zn, Cu, Pb, Fe Cr**, and AI thepolyacrylic acid has a molecular weight range of about 5,000 to 50,000and the hydrolyzed polyacrylamide has from 10 to 50 percent unhydrolyzedamide groups and a molecular weight of about 1,000 to 8,000, displacingsaid salt outwardly of the oil well into an oil bearing for mation, saidsalt being introduced in an amount effective to inhibit the formation ofscale in the oil well brine without plugging the formation.

2. The method of claim 1 wherein the polyacrylic acid has molecularweight range of about 17,000 to 50,000.

3. The method of claim 1 wherein polyacrylic acid has a molecular weightrange of about 20,000 to 30,000.

4. The method of claim 1 wherein said hydrolyzed polyacrylamide has amolecular weight of about 4,000 to 7,000.

5. The method of claim 1 wherein said relatively water-insoluble salt isdisplaced outwardly of said oil well into said formation in conjunctionwith a formation fracturing operation.

6. A method for inhibiting scale formation in oil well brines,comprising introducing into the oil well an acidic aqueous solution of awater-soluble salt of at least one of a polyacrylic acid having amolecular weight in the range of about 5,000 to 50,000 and a hydrolyzedpolyacrylamide having from 10 to 50 percent unhydrolyzed amide groupsand a molecular weight of from about 1,000 to 8,000 and awater-soluhydrolyzed polyacrylamide, said solution being introduced inan amount sufficient to produce the polyvalent metal salt of at leastone of the polyacrylic acid and hydrolyzed polyacrylamide in an amounteffective to inhibit the formation of scale in the oil well brinewithout plugging the formation.

7. The method of claim 6 wherein the water-soluble salt is awater-soluble salt of polyacrylic acid.

8. The method of claim 7 wherein said water-soluble salt of polyacrylicacid is a sodium polyacrylate and the water-soluble polyvalent metalsalt is a calcium salt.

9. The method of claim 7 wherein the water-soluble salt of polyacrylicacid is a sodium polyacrylate and the polyvalent metal salt is a zincsalt.

10. The method of claim 6 wherein the water-soluble salt is awater-soluble salt of hydrolyzed polyacrylamide.

11. The method of claim 10 wherein the water-soluble salt of hydrolyzedpolyacrylamide is a sodium polyacrylamide and the polyvalent metal saltis a calcium salt. v

12. The method of claim 10 wherein the water-soluble salt of hydrolyzedpolyacrylamide is a sodium polyacrylamide and the polyvalent metal saltis a zinc salt.

13. The method of claim 6 wherein the polyacrylic acid has a molecularweight range of about 17,000 to 30,000 and the hydrolyzed polyacrylamidehas from about 20 to about 40 percent unhydrolyzed amide groups and amolecular weight of about 4,000 to 7,000.

14. The method of claim 13 wherein said polyvalent metal salt is calciumpolyacrylate.

15. The method of claim 13 wherein said polyvalent metal salt is calciumpolyacrylamide.

16. The method of claim 13 wherein said polyvalent metal salt is zincpolyacrylate.

17. The method of claim 13 wherein said polyvalent metal salt is zincpolyacrylamide.

18. The method of claim 6 wherein the effective amount is about 0.1 to25 ppm in the produced water.

19. The method of claim 6 wherein said polyacrylic acid has a molecularweight range of about 17,000 to about 50,000.

20. The method of claim 6 wherein said polyacrylic acid has a molecularweight rangeof about 20,000 to 21. The method of claim 6 wherein saidhydrolyzed polyacrylamide has a molecular weight of from about 4,000 to7,000.

22. The method of claim 6 wherein the acid in said acidic aqueoussolution is at least one of hydrochloric,

ble salt of a polyvalent metal selected from the group sulfuric andacetic.

23. The method of claim 6 wherein said acidic aqueous solution is atleast in part neutralized by at least one of the produced fluids of saidwell and said well formation to precipitate said relativelywater-insoluble salt in situ in said formation.

2. The method of claim 1 wherein the polyacrylic acid has molecularweight range of about 17,000 to 50,000.
 3. The method of claim 1 whereinpolyacrylic acid has a molecular weight range of about 20,000 to 30,000.4. The method of claim 1 wherein said hydrolyzed polyacrylamide has amolecular weight of about 4,000 to 7,000.
 5. The method of claim 1wherein said relatively water-insoluble salt is displaced outwardly ofsaid oil well into said formation in conjunction with a formationfracturing operation.
 6. A method for inhibiting scale formation in oilwell brines, comprising introducing into the oil well an acidic aqueoussolution of a water-soluble salt of at least one of a polyacrylic acidhaving a molecular weight in the range of about 5,000 to 50, 000 and ahydrolyzed polyacrylamide having from 10 to 50 percent unhydrolyzedamide groups and a molecular weight of from about 1, 000 to 8,000 and awater-soluble salt of a polyvalent metal selected from the groupconsisting of alkaline earth metals, Zn , Cu , Pb , Fe , Cr , and Al ,the pH of the solution being below about 1.5, displacing said solutionoutwardly of the oil well into an oil bearing formation and then raisingthe pH of said solution to precipitate the polyvalent metal salt of atleast one of the polyacrylic acid and hydrolyzed polyacrylamide, saidsolution being introduced in an amount sufficient to produce thepolyvalent metal salt of at least one of the polyacrylic acid andhydrolyzed polyacrylamide in an amount effective to inhibit theformation of scale in the oil well brine without plugging the formation.7. The method of claim 6 wherein the water-soluble salt is awater-soluble salt of polyacrylic acid.
 8. The method of claim 7 whereinsaid water-soluble salt of polyacrylic acid is a sodium polyacrylate andthe water-soluble polyvalent metal salt is a calcium salt.
 9. The methodof claim 7 wherein the water-soluble salt of polyacrylic acid is asodium polyacrylate and the polyvalent metal salt is a zinc salt. 10.The method of claim 6 wherein the water-soluble salt is a water-solublesalt of hydrolYzed polyacrylamide.
 11. The method of claim 10 whereinthe water-soluble salt of hydrolyzed polyacrylamide is a sodiumpolyacrylamide and the polyvalent metal salt is a calcium salt.
 12. Themethod of claim 10 wherein the water-soluble salt of hydrolyzedpolyacrylamide is a sodium polyacrylamide and the polyvalent metal saltis a zinc salt.
 13. The method of claim 6 wherein the polyacrylic acidhas a molecular weight range of about 17,000 to 30,000 and thehydrolyzed polyacrylamide has from about 20 to about 40 percentunhydrolyzed amide groups and a molecular weight of about 4,000 to7,000.
 14. The method of claim 13 wherein said polyvalent metal salt iscalcium polyacrylate.
 15. The method of claim 13 wherein said polyvalentmetal salt is calcium polyacrylamide.
 16. The method of claim 13 whereinsaid polyvalent metal salt is zinc polyacrylate.
 17. The method of claim13 wherein said polyvalent metal salt is zinc polyacrylamide.
 18. Themethod of claim 6 wherein the effective amount is about 0.1 to 25 ppm inthe produced water.
 19. The method of claim 6 wherein said polyacrylicacid has a molecular weight range of about 17,000 to about 50,000. 20.The method of claim 6 wherein said polyacrylic acid has a molecularweight range of about 20,000 to 30,000.
 21. The method of claim 6wherein said hydrolyzed polyacrylamide has a molecular weight of fromabout 4,000 to 7,000.
 22. The method of claim 6 wherein the acid in saidacidic aqueous solution is at least one of hydrochloric, sulfuric andacetic.
 23. The method of claim 6 wherein said acidic aqueous solutionis at least in part neutralized by at least one of the produced fluidsof said well and said well formation to precipitate said relativelywater-insoluble salt in situ in said formation.